Controlling fracture geometry with the use of shrinkable materials

ABSTRACT

A method for treating a subterranean formation utilizing a composition having a plurality of shrinkable materials. The method of treatment may include providing a hydraulic fracture into the subterranean formation, and injecting a slurry having a plurality of shrinkable materials into a far field. The shrinkable materials may shrink once a threshold is reached.

BACKGROUND

Hydrocarbons (oil, condensate and gas) are typically produced from wells that are drilled into the formations containing them. For a variety of reasons, such as inherently low permeability of the reservoirs or damage to the formation caused by drilling and completion of the well, the flow of hydrocarbons into the well may be low. In this case, the well can be stimulated, using a variety of techniques, including hydraulic fracturing.

During the drilling of a wellbore, various fluids may be used for multiple functions. The fluids may be circulated through a drill pipe and a drill bit into the wellbore, and then may subsequently flow upward through the wellbore to the surface. During the circulation, the a fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate fluids from the formation by providing a sufficient hydrostatic pressure to prevent the ingress of the fluids onto the wellbore, to cool or lubricate the drill string and drill bit, and/or to maximize a penetration rate.

In hydraulic fracturing in particular, a fluid is injected into the formation to initiate and propagate a fracture. Then, a second fluid is injected to keep the fracture open after the pressure is released. During hydraulic fracturing, one or more of the fluids will be pumped into the wellbore until the downhole pressure exceeds the fracture gradient of the rock.

In hydraulic fracturing of horizontal wells and multi-layered formations, diverting techniques may be used to enable fracturing redirection between different zones. Known diverting methods include mechanical isolation devices such as packers, as well as well bore plugs, setting bridge plugs, pumping ball sealers, pumping slurred benzoic acid flakes and removable or degradable particulates.

When diversion using diverting materials is performed downhole, the diversion is generally based upon bridging of some particles of the diverting material and forming a plug by accumulating the rest of the particles at the formed bridge. However, when removable materials are used in a typical treatment diversion, the bridging ability of the diverting slurry may be reduced because of dilution with a wellbore fluid. Further, poor stability of the plug formed from various diverting materials is another concern during such a diversion procedure.

Plugging or diverting a downhole feature with solid diverting materials such as degradable materials may be achieved when the diverting agent is at a high loading (e.g., at a high concentration), such as from about 20 lbs/1000 gal to about 1000 lbs/1000 gal, or from about 40 lbs/1000 gal to about 750 lbs/1000 gal) in order to form temporary plugs or bridges. The solid diverting materials material may also be used at concentrations at least 4.8 g/L (40 lbs/1,000 gal), at least 6 g/L (50 lbs/1,000 gal), or at least 7.2 g/L (60 lbs/1,000 gal). High loading of the solid diverting materials may lead to multiple particle blocking of porous media. However, achieving a high loading of solid diverting materials within a stream of treatment fluid is challenging. The ability to add a solid into a treatment fluid in a continuous manner with traditional solid feeders so as to be functional in a particular operation downhole (such as a diverting and/or plugging operation) is difficult because the solid feeders are limited in their feeding rates. Because the treatment fluid is to be injected at a high rate, often exceeding 50 barrels (bbl)/min, the rate of addition of the solid should be substantial enough to create a stream of high loading solid material.

To aid in a diversion and/or plugging treatment, the solid material to be used may be a degradable material, and such material may be in the form of manufactured shapes such as flakes, fibers and particles. Methods for diversion using degradable materials is described in U.S. Pat. No. 7,380,600, U.S. Pat. No. 8,167,043, U.S. Pat. No. 7,565,929, and U.S. Patent Application Publication No. 2008/0210423, each of which is hereby incorporated by reference in its entirety. However, such known materials may not reliably operate efficiently, may cause congestion when passing through fracturing pumps and the like, and may necessitate substantial user intervention. Further, it may be desirable to control the geometry of a particular fracture. Controlling the geometry may be defined as stopping the propagation of a long fracture, which is desirable in cases where an excessively long fracture may interfere with a nearby well. Stopping the propagation of a fracture may result in generating a network of fractures rather than a simple bi-wing planar fracture, which may allow for desirable hydrocarbon retrieval. Also, stopping the propagation of a fracture may also promote height growth of a given fracture to contact a thicker pay-zone than the original fracture design would have allowed to contact. Another effect of stopping the propagation of a fracture may be to widen the fracture, which can place large proppant having a large diameter.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

The statements made merely provide information relating to the present disclosure, and may describe some embodiments illustrating the subject matter of this application.

In a first aspect, a method for providing a fracturing treatment to a subterranean formation is disclosed. The method may include producing a hydraulic fracture in the subterranean formation, and injecting a slurry into a far field. The slurry may include a plurality of shrinkable materials.

In another aspect, a method for controlling a fracture geometry of a subterranean formation is disclosed. The method may include producing at least one fracture in the subterranean formation, and injecting a slurry into a wellbore. The slurry may include a plurality of shrinkable materials. The method may further include penetrating the plurality of shrinkable materials into the at least one fracture, and the at least one fracture may be disposed at a far field.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1A and 1B show a diagram of a slurry according to one or more aspects.

FIGS. 2A and 2B show a diagram of a slurry being injected into a fracture and subjected to a temperature increase according to one or more aspects.

FIGS. 3A-3D show diagrams of a fracture during diversion and plugging according to one or more aspects.

FIG. 4 shows a diagram of a fracture during degradation of a plug according to one or more aspects.

FIGS. 5A and 5B show temperature profiles for pumping schedules according to one or more aspects.

FIG. 6 shows a degradation schedule of a fiber according to one or more aspects.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of the present disclosure. However, it may be understood by those skilled in the art that the methods of the present disclosure may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation—specific decisions may be made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. In addition, the composition used/disclosed herein can also comprise some components other than those cited. In the summary and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. The term about should be understood as any amount or range within 10% of the recited amount or range (for example, a range from about 1 to about 10 encompasses a range from 0.9 to 11). Also, in the summary and this detailed description, it should be understood that a range listed or described as being useful, suitable, or the like, is intended to include support for any conceivable sub-range within the range at least because every point within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each possible number along the continuum between about 1 and about 10. Furthermore, one or more of the data points in the present examples may be combined together, or may be combined with one of the data points in the specification to create a range, and thus include each possible value or number within this range. Thus, (1) even if numerous specific data points within the range are explicitly identified, (2) even if reference is made to a few specific data points within the range, or (3) even when no data points within the range are explicitly identified, it is to be understood (i) that the inventors appreciate and understand that any conceivable data point within the range is to be considered to have been specified, and (ii) that the inventors possessed knowledge of the entire range, each conceivable sub-range within the range, and each conceivable point within the range. Furthermore, the subject matter of this application illustratively disclosed herein suitably may be practiced in the absence of any element(s) that are not specifically disclosed herein.

The following definitions are provided in order to aid those skilled in the art in understanding the detailed description.

The term “injecting” describes the introduction of a new or different element into a first element. In the context of this application, injection of a fluid, solid or other compound may occur by any form of physical introduction, including but not limited to pumping.

The term “fracturing” refers to the process and methods of breaking down a geological formation and creating a fracture, i.e., the geological formation around a wellbore, in order to increase production rates from a hydrocarbon reservoir. The fracturing methods otherwise use techniques known in the art. Fractures can also be natural fractures that already existed in the rock. Those natural fractures may be opening as a result of the net pressure developing in the main fracture during the treatment.

The term “near field” relates to a distance from a surface of the wellbore. A distance within the near field may be a distance of 0 to about 50 feet from the wellbore surface, or 0 to about 10 feet from the wellbore surface, or 0 to about 5 feet from the wellbore surface.

A diverting composition can be used in all portions of the subterranean formation penetrated by a wellbore, including portions that are substantially distanced from the wellbore. The terms “substantially distanced from the wellbore,” or “far field,” may refer to any portion of the subterranean formation that is not near wellbore, outside of a perforation tunnel or outside of a formation face in openhole configuration. These portions of the subterranean formation may be beyond the range where conventional diverting agents can reach. For example, far field may refer to the subterranean zone that is from about 10 feet to about 3000 feet from a wellbore or perforation tunnel, or from about 100 to about 1000 feet from a wellbore or perforation tunnel. A zone within the far field may further be a distance of about 30 feet or more from the wellbore surface, or about 50 feet or more from the wellbore surface, or 50 to 100 feet from the wellbore surface.

The term “degradable materials” refers to a material that will at least partially degrade (for example, by cleavage of a chemical bond) within a desired period of time such that no additional intervention is used to remove the plug. For example, at least 30% of the material may degrade, such as at least 50%, or at least 75%. In some situations, 100% of the material may degrade. The degradation of the material may be triggered by a temperature change, and/or by chemical reaction between the material and another reactant. Degradation may include dissolution of the material.

The terms “shrinkable materials” refer to materials that have the capacity to reduce in at least one size dimension, such as length, diameter, mass and/or volume in response to a given stimulus, including but not limited to an increase in temperature.

The terms “shrinkable fibers” fibers that have the capacity to reduce in at least one size dimension, such as length, diameter, mass and/or volume in response to a given stimulus, including but not limited to an increase in temperature.

A diverting or plugging operation may involve controlling a particular fracture, perforation or opening by injecting a plugging material into an appropriate location, so as to, for example, protect from fluid loss at the fracture or perforation. The fracture which is plugged may be a fracture intersecting the wellbore, or a fracture that intersects an existing fracture at a distance away from the wellbore. One may want to plug a fracture that is intentionally induced, or a natural fracture of the rock. The diversion or plugging operation may occur by using materials, such as shapeable materials including shrinkable materials, which in some instances may be shrinkable fibers, that can create a temporary blocking effect that can be removed, for example, by degradation of the material, following the treatment.

In some embodiments, a fracturing treatment is performed. The method may first involve hydraulic fracturing, and can be used in vertical wells, horizontal wells, or a combination thereof. The hydraulic fracturing may include pumping a fracturing fluid into a wellbore until a predetermined time. The predetermined time may be a time where the downhole pressure exceeds a fracture gradient of the rock.

To enable a fracture to remain open for an amount of time, a propping agent may be introduced into the fracture. The propping agent may include any suitable solid material, including but not limited to sand, ceramic materials, gels, and foams.

In some embodiments, before, after or while a hydraulic fracture is initiated, the method may involve designing a composition and treatment schedule. The composition and treatment schedule may be used for diverting or plugging a fracture, or more generally for any purpose within the context of a fracturing treatment. The composition may include a plurality of shrinkable materials. The composition may include additional particles, such as small particles, in addition to the plurality of shrinkable materials. The composition may include a degradable material. The degradable material may be a shrinkable material.

The initial shapes of suitable shrinkable materials may include fibers, films, ribbons, platelets, flakes and other shapes having an aspect ratio from about 20 to 2000, or from about 100 to 1000 (the aspect ratio of a flake, ribbon or film is the ratio of the average surface area to the average thickness). The differences in the compositions of the different components, and their consequent differences in behavior when subjected to changes in conditions downhole (such as differences in shrinkage or elongation with differences in temperature or with sorption of fluids such as oil and water or, with differences of sorption of fluids such as oil and water, or with changes in pH or salinity) are responsible for the changes in shape.

One example of the shrinkable material is a shrinkable fiber. Shrinkable fibers may include single-component materials, for example polylactic acid fibers. In general, fibers made from amorphous polymers may be shrinkable. Shrinkable fibers may be comprised of multicomponent materials, for example multicomponent fibers, such as, for example two-component fibers. Common structures of multicomponent fibers, for example side-by-side, sheath-core, segmented pie, islands-in-the-sea, and combinations of such configurations, and methods of forming such multicomponent fibers, are well known to those of ordinary skill in the art of making fibers. For example, such fibers and methods of making them are described in U.S. Pat. No. 7,851,391, which is hereby incorporated by reference in its entirety.

For shapeable materials in the shape of shrinkable fibers, there may be a capability for the fibers to shrink from about 20 to about 80 percent of their initial length or mass, or shrinkage of from about 40 to about 70 percent of length or mass, although less or more shrinkage is suitable. Other suitable materials may readily be identified or conceived of by readers of this disclosure.

One example of suitable shapeable material having shrinkable fibers is two-component fibers made of a core material and a sheath material that have different melting points. The core material (for example a thermoplastic resin, for example a polypropylene or a polyester) normally is used to ensure the integrity of the material during use; this core is not normally melted as the shapeable material is reshaped, and may, for example, form a three-dimensional network in the newly shaped subsequent structure, giving the subsequent structure strength. The sheath material (for example a thermoplastic resin, for example a polyethylene) has a lower melting and bonding temperature and thus may be used to hold the subsequent structure together and in the new shape. The melting point of the sheath material may be about 80° C.; the melting point of the core material may commonly be up to about 160° C. Such materials may be manufactured with the sheath and core eccentric or concentric, and the fibers may be available in conventional form or available commercially already in a crimped (zigzag), wavy, or spiral form. Such fibers are available, for example, from ES Fibervisions™. Such shrinkable fibers are described in U.S. Patent Application Publication No. 2010/0227166, which is herein incorporated by reference.

Another example of suitable shapeable materials is highly shrinkable copolyamide fiber (having high wet heat shrinkage characteristics and low dry heat shrinkage characteristics) as disclosed by Toray Industries, Inc. A suitable fiber is described in JP 08-209444, which is herein incorporated by reference. Another suitable fiber is a staple fiber obtained by extruding a copolyester including (A) isophthalic acid and (B) 2,2-bis{4-(2-hydroxyethoxy)phenyl}propane as copolymerizing components, as described in JP 10-0204722, which is herein incorporated by reference. This latter fiber undergoes less than or equal to 20 percent shrinkage in boiling water, and 12 to 40 percent shrinkage in 160° C. dry air after treating in boiling water.

Yet another example of suitable shapeable materials is a polyester fiber having a diol component and a dicarboxylic acid component; for example the diol may be 1,1-cyclohexanedimethanol or its ester-forming derivative (or biphenyl-2,2′-dicarboxylic acid or its ester-forming derivative) in an amount of 2 to 20 mole percent based on the whole dicarboxylic acid component. Such fibers were disclosed by Kuraray in JP 9-078345 and JP 8-113825, each of which are herein incorporated by reference. Other suitable materials from Kuraray include the polyester fibers described in U.S. Pat. No. 5,567,796, which is herein incorporated by reference.

Nippon Ester Company Ltd. has described several fibers suitable for use as shapeable materials. A highly shrinkable conjugated fiber disclosed in JP 2003-221737, which is herein incorporated by reference, is composed of a polyester, A, containing polyethylene terephthalate as a main component (prepared by copolymerizing an aromatic dicarboxylic acid having a metal sulfonate group in an amount of from 3 to 7 mole percent based on the whole acid component or an isophthalic acid in an amount of from 8 to 40 mole percent) and a polyester, B, that is ethylene terephthalate. The difference in melting points between polyester A and polyester B is at least 5° C. and the difference between the heat of melting of polyester A and polyester B is at least 20 J/g. The dry heat shrinkage at 170° C. is at least 15 percent.

Another fiber described by Nippon Ester Company Ltd. in JP 08-035120, which is herein incorporated by reference, is a highly shrinkable polyester conjugated fiber obtained by conjugate spinning in a side-by-side fashion of polyethylene terephthalate and a polyethylene terephthalate copolymerized with 8 to 40 mole percent of isophthalic acid at a weight ratio of from 20:80 to 70:30. The product having a single fiber fineness of 1 to 20 denier has a hot water shrinkage at 90° C. of from 70 to 95 percent.

Kaneka Corporation has described several fibers suitable for use as shapeable materials in embodiments described herein in U.S. Patent Application Publication No. 2002/0122937 and U.S. Pat. No. 7,612,000, each of which are herein incorporated by reference. They include a hollow shrinkable copolymer fiber made of acrylonitrile and a halogen-containing vinyl monomer manufactured by wet spinning followed by steam treatment, drying, and heating. Some examples contain one or more of acrylic acid, methacrylic acid, vinyl chloride, vinylidene chloride, vinyl esters (for example vinyl acetate, vinyl pyrrolidone, vinyl pyridine and their alkyl-substituted derivatives), amides, and methacrylic acid amides. In these references, one of the monomers may be halogen-containing to provide fire-resistance to the fiber; in the present application, this is not necessary. Other examples are modacrylic shrinkable fibers made from 50 to 99 parts by weight of a polymer (A) containing 40 to 80 weight percent acrylonitrile, 20 to 60 weight percent of a halogen-containing monomer, and 0 to 5 weight percent of a sulfonic acid-containing monomer, and 1 to 50 parts by weight of a polymer (B) containing 5 to 70 weight percent acrylonitrile, 20 to 94 weight percent of an acrylic ester, and 16 to 40 weight percent of a sulfonic acid-containing monomer containing a methallylsulfonic acid or methallylsulfonic acid metal salt, and no halogen-containing monomer. Some examples of the fibers contain from 10 to 50 percent voids, and shrink at least 15 percent (and often over 30 percent) at from 100 to 150° C. in 20 minutes. They may be crimped before use.

KB Seiren Ltd. has described in U. S. Patent Application Publication No. 2010/0137527, which is herein incorporated by reference, a fiber that is suitable for shapeable materials. It is a highly shrinkable (for example in boiling water) fiber that is composed of a mixture of a nylon-MXD6 polymer (a crystalline polyamide obtained from a polymerization reaction of metaxylenediamine and adipic acid) and a nylon-6 polymer in a weight ratio of from 35:65 to 70:30. The fiber is made by melt spinning and drawing or draw-twisting. The fiber shrinks 43 to 53 percent in hot water at from 90 to 100° C. Inorganic particles, for example TiO₂, may be added to improve the spinning process.

Shimadzu Corporation described in U.S. Pat. No. 6,844,063, which is herein incorporated by reference, a core-sheath conjugated fiber, that is suitable as a shapeable material, made from a sheath of (A) a low heat-shrinkability component that is a highly crystalline aliphatic polyester (having a melting point above 140° C.) and a core of (B) a high heat-shrinkability polymer containing at least 10 percent by weight of a low crystallinity aliphatic polyester having a melting point lower than that of component (A) by at least 20° C. The difference in shrinkability is at least 3 percent, or about 5 to about 70 percent, or about 10 to about 50 percent.

Kanebo Ltd. described, in Japanese Patent No. JP 7-305225, which is herein incorporated by reference, highly shrinkable polyester staple polymers obtained by melt-spinning a polymer made from a polyethylene terephthalate and subjecting it to specified melt-spinning drawing and post-treating processes under specified conditions. Examples include polyethylene terephthalate core-sheath structures with in which the core and sheath have different crystallinities.

U.S. Pat. No. 6,844,062, which is herein incorporated by reference, describes spontaneously degradable fibers and goods made with fibers having a core-sheath structure including (A) a low heat-shrinkable fiber component comprising a high crystalline aliphatic polyester and (B) a high heat-shrinkable fiber component comprising an aliphatic polyester, for example a low crystalline or non-crystalline aliphatic polyester. Examples of polymer (A) include homopolymers such as polybutylene succinate (melting point about 116° C.), poly-L-lactic acid (m.p. 175° C.), poly-D-lactic acid (m.p. 175° C.), polyhydroxybutyrate (m. p. 180° C.) and polyglycolic acid (m.p. 230° C.), and copolymers or mixtures of these with small amounts of other components. Polymer (B) is a component having a low crystallinity and a high heat shrinkability. The component used for the copolymerization or mixing with the homopolymers with high melting point such as polybutylene succinate, polylactic acid, polyhydroxybutyrate and polyglycolic acid can be suitably selected from the raw materials for the preparation of the above-mentioned aliphatic polyesters.

Yet another suitable shapeable material is described in U.S. Pat. No. 5,635,298, which is herein incorporated by reference. It is a monofilament having a core-sheath structure including a core of a thermoplastic polyester or copolyester and a sheath of a thermoplastic polyester, in which the polyester or copolyester of the core has a melting point of about 200 to about 300° C., or about 220 to about 285° C., and includes at least 70 mole percent, based on the totality of all polyester structural units, of structural units derived from aromatic dicarboxylic acids and from aliphatic diols, and not more than 30 mole percent, based on the totality of all polyester structural units, of dicarboxylic acid units which differ from the aromatic dicarboxylic acid units which form the predominant portion of the dicarboxylic acid units, and diol units derived from aliphatic diols and which differ from the diol units which form the predominant portion of the diol units, and the sheath is made of a polyester mixture containing a thermoplastic polyester whose melting point is between about 200 and about 300° C., or between about 220 and about 285° C., and a thermoplastic, elastomeric copolyether-ester with or without customary nonpolymeric additives. The core-sheath monofilaments, if the core and sheath materials are separately melted and extruded, then cooled, then subjected to an afterdraw and subsequently heat-set, under conditions as specified in the patent, may have a dry hear shrinkage at 180° C. of from 2 to 30 percent.

U.S. Pat. No. 5,688,594, which is herein incorporated by reference, describes a hybrid yarn, the fibers of which are suitable shapeable materials for embodiments described herein. The hybrid yarn contains at least two varieties of filaments: (A) has a dry heat shrinkage of less than 7.5%, and (B) has a dry heat shrinkage of above 10%. Appropriate heating forces the lower-shrinking filaments to undergo crimping or curling. (A) is, for example, aramid, polyester, polyacrylonitirile, polypropylene, polyetherketone, polyetheretherketone, polyoxymethylene, metal, glass, ceramic or carbon, and (B) is, for example, drawn polyester, polyamide, polyethylene terephthalate, or polyetherimide.

In general, the lower limit for fiber diameter for typical shrinkable organic fibers may be about 1.3 dtex (11 microns), which is based primarily on current manufacturing limitations. The upper limit is based on limitations of typical oilfield pumping equipment. On a weight basis, the larger the fiber diameter, the less the total fiber length that is pumped and the fewer fiber filaments are pumped. However, in embodiments described here, shapeable fibers are pumped along with proppant. Under such circumstances up to about 4.4 dtex fiber can be pumped with present-day equipment. The length of the shrinkable fibers prior to shrinkage may be about 2 mm to 30 mm, or from about 3 mm to 10 mm.

One example of shrinkable material is shrinkable film. Shrinkable film may include single-component materials, for example polyvinyl chloride, polylactic acid, oriented polystyrene. Shrinkable films may be comprised of multicomponent materials, for example multicomponent films, such as for example polyethylene terephthalate and polylactic acid.

The shrinkable materials included in the composition may allow for agglomerations to be formed during a diverting and/or plugging treatment, and can enhance the bridging mechanism. The agglomerations formed by the shrinkable materials may be small enough to pass through some perforations within the wellbore but may allow for a plugging of a fracture or desired perforation by attaching to the fracture or perforation entrance.

The shrinkable materials may be used alone or mixed with a choice or mixture of chemically active and/or chemically inert materials. By non-limiting example, shapeable elongated particles, including a plurality of small particles, may be included in the composition. Further, the shrinkable materials may have a low bridging tendency which may allow for a reduction of the fiber being caught into the fracture, and thereby allow for an increase in fracture complexity and/or ability to control a fracture geometry.

The plurality of small particles may be any suitable particles, including but not limited to particles of a size smaller than about 1000 microns or about 800 microns. In some embodiments, the small particles may be of a size in a range of 20/40 mesh, which corresponds to a size range of 432 to 838 microns. Even smaller particles may be used, such as 100-mesh size particles (150 microns). One skilled in the art may also understand small particles to be particles of a size capable of being grabbed and/or entangled within by the shrinkable materials.

The small particles may be non-degradable, such as particles of a proppant and/or sand, but also may be degradable. The small particles can be of any suitable shape. If non-degradable, the particles can be left behind as proppant for the fracture. If that is the case, then sphericity of the proppant may be considered to select the appropriate small particles so as to ensure conductivity of the fracture.

The composition to be used in the treatment may further include a carrier fluid such as a linear gel. The carrier fluid may be included as a part of the slurry or pill, and/or using one or more spacers. The use of spacers is optional. In the embodiments described further herein, the composition includes a slurry comprising the shrinkable materials, without the use of spacers. However, the use of a pill and spacers is understood to be within the scope of this disclosure.

In FIGS. 1 and 2, fibers are used in Figures as means of illustration of shrinkable materials. Referring to FIGS. 1A and 1B, the composition to be used in the treatment may include a slurry 1. The slurry 1 may be injected into the wellbore 2.

The composition according to some embodiments thus may include a diversion slurry including shrinkable materials and/or including additional small particles, and one or more spacers including a base fluid and fibers or other materials. In some embodiments, the amount of shrinkable materials in the pill may be about 0.1 to 30 pounds per thousand gallons (ppt), or about 1 ppt to about 10 ppt. The amount of small particles in the pill may be about 20 ppt to about 5000 ppt, or about 100 ppt to about 1000 ppt. Carrier fluid may include a viscosifier such as guar or surfactant. A suitable carrier fluid may be water containing about 5 to 40 ppt of guar, or about 20 ppt of guar. A possible ratio of amount of fiber to small particles is about 0.1 to about 1, or about 0.2 to about 0.7.

The shrinkable materials may be added in a portion of fluid that does not include any proppant or other particles. In some embodiments, the shrinkable materials may be added to the pad, which is a portion of the fluid before any addition of proppant. The shrinkable materials may be added to the pad alone, or along with other shapeable materials. The shrinkable materials optionally along with other shapeable materials may synergistically act to form a plug.

After designing of the composition, the composition including at least the diversion slurry can be delivered from the wellbore surface to a downhole portion of the wellbore so as to reach a fracture in the wellbore. In some situations, the composition includes about 5 bbls to about 30,000 bbls of a carrier fluid, such as water, gel or the like in addition to the diversion pill. The composition may be pumped downhole to a distance of about 50 ft to about 20,000 from the surface of the wellbore, or at least 100 feet or at least 200 feet from the surface of the wellbore. The composition may be pumped downhole until it reaches a fracture or other location where a diverting or plugging action may commence.

The composition may be pumped as a pill, or continuously during the fracturing treatment (whereby the shrinkable fiber may be added for the entire treatment). The composition may also be ‘pulsed’ such that stages of diverter-loaded slurry alternate with stages of diverter-free slurry. Pulses may range from about 5 seconds to about 1 minute, resulting in pulses of volume ranging from about 50 bbl to about 6000 bbl.

In the embodiment described herein, the slurry ultimately reaches a fracture within the far field region. Further, the shrinkable materials within the slurry may not begin shrinking until the far field is reached, that is, until a distance of 30 feet or more, or 50 feet or more, or 50-100 feet, or 50-75 feet, from the wellbore is reached. However, it would be understood by one skilled in the art that the slurry may begin shrinking at a point prior to the far field, and may not even reach the far field in the first place. Of note, U.S. patent application Ser. No. 14/486,720, which is herein incorporated by reference in its entirety, includes embodiments where shrinkable fibers commence shrinking at a wellbore surface or at a distance before the far field.

At some point between the designing and preparation of the composition and the completion of the diverting or plugging action, at least some of the plurality of shrinkable materials will undergo a shrinking process. The shrinking of the shrinkable materials may begin in response to a temperature of the slurry, which may be increased mechanically, chemically, and/or electrically. The temperature of the slurry may be manipulated by a user, such as on a wellbore surface or at a distance below the wellbore surface. The temperature of the slurry may alternatively or additionally change in connection with a higher ambient temperature as the slurry travels down the wellbore. The slurry composition and particularly the shrinkable materials may be particularly designed and selected in view of temperature thresholds of such shrinkable materials, and thus may be selected based upon their ability to shrink in response to a controlled or ambient temperature at a point prior to or during injection.

Referring to FIGS. 2A and 2B, after exposure to the triggering temperature and a certain amount of time, the shrinkable materials, which may be shrinkable fibers, may change shape during pumping into a high bridging aperture that cause plugging in the fracture. Accordingly, once a triggering temperature or other threshold is reached, shrinkable materials in the slurry 1 begin to shrink, and solid agglomerations 1A may be formed. The triggering temperature may be reached at some distance within the far field. These solid agglomerations may further include proppant, such as sand, and/or additional particles, such as the small particles described herein. The slurry 1 may begin to form its solid agglomerations at some distance from the surface of the wellbore, such as at the far field. The mechanical energy of the shrinking shrinkable materials can move proppant and/or particles within the slurry to combine with the shrinkable materials and form solid agglomerations.

Referring to FIG. 3A, the slurry comprising the shrinkable materials may be used to plug a fracture 3 at a given distance from the wellbore, forming plugs 3A and 3B on the ends of the fracture. The depth of the penetration of the materials into the fracture 3 may be controlled by temperature. That is, if the temperature is increased to a point where shrinkable materials shrink to a particular extent, the depth of penetration of the materials may increase. The depth of penetration of the materials into a fracture may be any depth, including about 30 ft, about 50 ft or about 100 ft. The depth of penetration of materials is not necessarily limited by the tip of the fracture.

Referring to FIG. 3B, plugging of a fracture tip may occur. The plugging may be a result of the solid agglomerations that were formed as a result of shrinking of the shrinkable materials. The plugged fracture tips 3A-3C may comprise an amount of slurry which may further comprise an amount of shrunk shrinkable materials. Additional fracture diversion may occur pursuant to the plugging of the fracture tips. Additional fractures 4 may be formed, the additional fractures optionally being connected, either directly or indirectly, to the original fracture 3, so as to increase the complexity or otherwise change the geometry of the fracture 3. The fracture 3 may thus be changed from a binary or biplanar fracture to a fracture having a higher complexity, such as having secondary and tertiary fractures extending from a main fracture. The fracture 4 and any additional fractures may be propagated with additional pumping of the slurry. Such changed geometry and/or increased complexity may, for example, allow for more surface area of contact between the fracture network and the rock, allowing for more production rate and more ultimate recovery of hydrocarbon.

The side fractures may be created by having a bridge formed in a main fracture while pressure in the main fracture rises and slurry is pumped. As pressure rises, weak points lead to initiation of fracture, or some pre-existing natural fractures open. Once the fractures are either initiated or reopen, then they may be propagated.

Note that far field diversion is working in those formations that are heterogeneous by nature and have many weak points, natural fractures that are existing.

Referring to FIG. 3C, fracture shape change may occur pursuant to the plugging of the fracture tip. The fracture width may increase from a dimension d1 to d2. Such increase width may allow for a larger proppant diameter to be placed in the fracture allowing for more fracture conductivity and for more production rate.

Referring to FIG. 3D, fracture shape change may occur pursuant to the plugging of the fracture tip. The fracture height may increase from a dimension h1 to h2. Such increase height may, for example, allow for contacting a thick pay zone, allowing for more production rate and more ultimate recovery of hydrocarbon.

Referring to FIG. 4, at a particular point after the fracturing treatment is completed, degradation of at least some portions of the composition may commence. As shown in FIG. 4, the fractures 3 and 4 no longer include the plugged fracture tips 3A-3C, as the plugs can degrade after a predetermined time and may be removed from the plug zone or wellbore, following degradation, by any suitable method. The degradation may occur mechanically, chemically or electrically, and may be owed to the degradable material within the slurry and/or shrinkable materials themselves. In embodiments where degradable material in addition to the shrinkable materials is used, the degradable material may include one or more of powder, beads, chips and an additive for accelerating degradation. Owing to this degradation, the plug of a fracture may disappear and hydrocarbon may flow into the wellbore.

The predetermined temperature threshold may be any suitable temperature to enable the shrinkable materials to shrink to a predetermined percentage. If fibers are used as shrinkable material, shrinkage of about 20 to about 80 percent of the shrinkable fibers' initial length or mass or shrinkage of from about 40 to about 70 percent of the shrinkable fibers' initial length or mass may be affected. The temperature that causes the fibers to begin shrinking may be about 20 to about 160° C., or about 30 to about 50° C., or about 40 to about 42° C. Further, FIGS. 5A and 5B show different pumping schedules and the relationship between distance and temperature threshold. The temperature threshold may increase as distance from the wellbore increases, as shown in the schedule shown in FIG. 5A and also the schedule shown in FIG. 5B.

The shrinkable materials may begin shrinking at any point prior to or during pumping. In some embodiments, the shrinking may occur at any distance within the far field, such as at a distance of at least 30 feet below the wellbore surface, or at least 50 feet below the wellbore surface, or about 50 to about 100 feet below the wellbore surface.

Referring to FIG. 6, the shrinkable materials will shrink in mass over a period of time. In some aspects, shrinkage of 20% of the fibers' mass may be about 5 hours (see Sample 1) to about 7 hours (see Sample 2). Further, shrinkage of 80% of the fibers' mass may be about 16 hours (Sample 1) to about 28 hours (Sample 2). 100% mass shrinkage may be found at about 19 hours (Sample 1) to about 36 hours (Sample 2).

The above-described treatment may be repeated as desirable and may allow for temporary isolation for additional fracture diversions within a particular wellbore. Additionally, the above-described treatment may be suitable for a treatment in a shale formation, but may also be suitable for other rock formations where hydrocarbon drilling may occur.

Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods and uses, such are within the scope of the appended claims. 

What is claimed is:
 1. A method of providing a fracturing treatment to a subterranean formation, comprising: producing a hydraulic fracture in the subterranean formation; and injecting a slurry into a far field, wherein the slurry includes a plurality of shrinkable materials.
 2. The method of providing the fracturing treatment according to claim 1, further comprising shrinking the shrinkable materials by increasing a temperature of the slurry.
 3. The method of providing the fracturing treatment according to claim 1, further comprising degrading the shrunk materials after a predetermined time.
 4. The method of providing the fracturing treatment according to claim 1, wherein the plurality of shrinkable materials comprise at least one amorphous polymer.
 5. The method of providing the fracturing treatment according to claim 1, wherein the plurality of shrinkable materials comprise polylactic acid.
 6. The method of providing the fracturing treatment according to claim 1, wherein the shrinkable material has shapes having an aspect ratio from about 20 to about
 2000. 7. The method of providing the fracturing treatment according to claim 1, wherein the shrinkable material is a fiber or a film.
 8. The method of providing the fracturing treatment according to claim 1, wherein the far field is at least 50 feet from a surface of a wellbore.
 9. The method of providing the fracturing treatment according to claim 8, wherein the fracturing treatment includes controlling the fracture geometry.
 10. The method of providing the fracturing treatment according to claim 1, wherein the slurry further comprises a degradable material.
 11. The method of providing the fracturing treatment according to claim 10, wherein the further degradable material comprises one or more of powder, beads, chips, and an additive for accelerating degradation.
 12. A method of controlling a fracture geometry of a subterranean formation, comprising: producing at least one fracture in the subterranean formation; injecting a slurry into a wellbore, wherein the slurry includes a plurality of shrinkable materials; and penetrating the plurality of shrinkable materials into the at least one fracture, wherein the at least one fracture is disposed at a far field.
 13. The method of controlling a fracture geometry of a subterranean formation, according to claim 12, further comprising: after the slurry is injected into the wellbore, forming at least one solid agglomeration of particles comprising at least some of the plurality of shrinkable materials to thereby create a plug for the at least one hydraulic fracture.
 14. The method of controlling a fracture geometry of a subterranean formation according to claim 13, further comprising performing fracture diversion by means of the plugging of the at least one hydraulic fracture.
 15. The method of controlling a fracture geometry of a subterranean formation according to claim 12, further comprising: controlling a temperature of the shrinkable materials to allow for the shrinkable materials to shrink upon being located within the fracture at a predetermined distance from a wellbore.
 16. The method of controlling a fracture geometry of a subterranean formation according to claim 15, further comprising degrading the shrunk materials after a predetermined time.
 17. The method of controlling a fracture geometry of a subterranean formation according to claim 12, wherein the predetermined distance from the wellbore is within the far field.
 18. The method of controlling a fracture geometry of a subterranean formation according to claim 12, wherein the far field is at least 50 feet from a surface of a wellbore.
 19. The method of controlling a fracture geometry of a subterranean formation according to claim 12, further comprising injecting additional slurry into the far field.
 20. The method of controlling a fracture geometry of a subterranean formation according to claim 19, further comprising creating additional fractures by means of the injection of the additional slurry.
 21. The method of controlling a fracture geometry of a subterranean formation according to claim 19, further comprising creating at least one plug by means of the injection of the additional slurry. 